Fortnightly - Renewable powerhttp://www.fortnightly.com/tags/renewable-power
enGreen Dealinghttp://www.fortnightly.com/fortnightly/2012/04/green-dealing
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Renewable M&amp;A lives on despite death of Treasury cash grants.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Brian Boufarah and Marlene Motyka</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Business &amp; Money</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Brian Boufarah</b> (<a href="mailto:bboufarah@deloitte.com">bboufarah@deloitte.com</a>) is a partner with Deloitte &amp; Touche LLP. <b>Marlene Motyka</b> (<a href="mailto:mmotyka@deloitte.com">mmotyka@deloitte.com</a>) is a principal with Deloitte Financial Advisory Services LLP.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">April 2012</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1204/images/1204-BIZ-figs1-2.jpg" width="1422" height="1813" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1204/images/1204-BIZ-fig3.jpg" width="2068" height="2037" alt="" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1204/images/1204-BIZ-fig4.jpg" width="1404" height="913" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>The U.S. Treasury cash grants for new renewable power projects expired at the end of 2011. These incentives, which were implemented under Section 1603 of the <i>American Recovery and Reinvestment Act</i> of 2009, helped to support continued capacity additions throughout the recession. The impending expiration of these grants caused a wave of merger and acquisition (M&amp;A) activity during 2011 as developers and financiers rushed to get deals done and to begin construction in order to meet the Section 1603, 5-percent safe harbor threshold by the Dec. 31, 2011 deadline.</p>
<p>With a history of fluctuating tax policy, the renewable power sector is accustomed to moving swiftly to take advantage of incentives. But even before this recent dash to the latest finish line, M&amp;A activity in the renewables industry had been gaining momentum. Renewable deal activity strengthened in the five-year period from 2007 through 2011, with a notable exception. Activity dipped in the second half of 2008 because of the economic slowdown; however, it rebounded about a year later due to favorable government incentives and regulations.<sup>1 </sup></p>
<p>Over the last five years, wind has been the most popular subsector for renewable power M&amp;A due to a more mature market and government incentives. M&amp;A activity in wind, however, began trailing off in 2010 as low natural gas prices put increased pressure on the economics of wind. In contrast, solar deals gained momentum as falling panel prices made project economics more viable and as installed capacity increased. Utility-scale solar development also came on the scene, further encouraging deal activity. Meanwhile, M&amp;A for biomass was limited due to feedstock supply and transportation constraints, but the subsector still managed to pique the interest of utilities seeking innovative ways to meet renewable portfolio standards. The geothermal and hydro subsectors, on the other hand, were relatively inactive, recording only a few transactions per year. This wasn’t unexpected, considering that hydro is well-established with limited new projects on the horizon, and only a handful of large companies are presently capable of and interested in pursuing geothermal initiatives since they require large capital investments and long lead times <i>(see Figure 1). </i></p>
<p>Much of the deal activity during this five-year period has been composed of companies seeking to grow through acquisition of developers and individual projects. But lately, another kind of union has been gaining ground. Joint ventures (JV) have been on the rise as companies look to share both costs and risks and collaborate on new technologies. Since developers often have limited capital, this strategy also allows them to leverage the stronger balance sheets of JV partners to fund construction <i>(see Figure 2).</i> Additionally, this approach enables environmentally friendly investors to claim credit for being involved in a greater magnitude of projects and overall megawatts for relatively lower investment dollars.</p>
<h4>Tax Policy Matters</h4>
<p>Although different deals took different forms, the recent increase in renewable M&amp;A activity can be attributed largely to U.S. federal tax policy. Quite simply, tax credits have propelled new installations, which correlate positively with M&amp;A deal activity.</p>
<p>In some cases, tax policy is creating an environment that fosters deal activity, while in others it’s doing the opposite. For instance, the investment tax credits (ITC) for solar power have been extended until 2016, providing longer-term confidence to investors. The production tax credits (PTC) for wind power, in contrast, have followed a cycle of lapse and reinstatement since their initial introduction in 1992. The industry tends to experience strong growth while the PTC is firmly in place, as well as in the years leading up to its expiration. Lapses in the PTC then cause a dramatic slowdown in the implementation of planned wind projects. Upon restoration, the wind subsector takes time to recover, and then experiences strong growth until the tax credits expire. And so on. At present, the PTCs for wind are due to expire at the end of 2012 <i>(see Figure 3). </i></p>
<p>And no discussion of federal tax policy is complete without considering the impact of the Treasury cash grants, which are available only for renewable power projects placed in service after 2011 if they began construction before 2012. These grants were a game-changer for renewable energy developers during the financial crisis, allowing the industry to maintain momentum during a period of severe financial shock. For example, in the wind space, Treasury cash grants removed the need for U.S. taxable income in order to take advantage of PTCs by giving investors a cash grant in lieu of the tax credits. The grant was equal to 30 percent of the eligible cost of the project, and it could be received 60 days after project completion. This helped to bridge the gap during the financial crisis as many of the traditional tax-equity investors either dropped out or pulled back. The cash grants also opened the door to additional investors, including foreign players who previously couldn’t benefit from the PTCs or ITCs since they had no U.S. tax appetite. Additionally, the grants drew the attention of private equity and infrastructure investment funds.</p>
<p>Many proponents of renewable power see the recent expiration of the Treasury cash grants as a major blow. This event, along with the impending expiration of PTCs for wind at the end of 2012, is raising questions about the future prospects for the industry as a whole. Will renewable power development, and accordingly M&amp;A activity, soon face a precipitous decline?</p>
<h4>Mixed Outlook</h4>
<p>The possibility of a drop-off in deal opportunities is a legitimate concern, especially considering that other market dynamics could contribute to an unfavorable climate for renewable development. Among them are low natural gas prices. This is putting downward pressure on power prices, which is squeezing returns for developers. Perhaps most troubling to proponents of renewable energy is that there’s no end in sight. Shale gas production is soaring in the United States, with current forecasts predicting a three-fold increase from 2009 to 2035.<sup>2</sup> With an abundance of domestic supplies, natural gas prices likely will remain low in the near-term. The reliability, affordability and baseload capability of natural gas, along with its lower emissions profile, suggest that it likely will emerge as a strong competitor to renewables for the next tranche of generation build in the U.S.</p>
<p>Partly due to the shale gas boom, developers are finding that power purchase agreements (PPA) aren’t only yielding lower prices for energy, but they’re also becoming more difficult to obtain. Renewable power developers in particular are under tremendous pressure to secure long-term PPAs to obtain financing. In addition, the future need for renewable power among utilities remains uncertain, although renewable portfolio standards (RPS) are in effect in many states.</p>
<p>Another limiting factor is overall demand for energy, which remains relatively low in the U.S. post recession. Some of this deterioration might be due to increases in energy efficiency by consumers and businesses as well as changes in behavior. In a recent survey of consumer and business attitudes regarding energy and energy usage conducted by Deloitte and Harrison Group, 90 percent of consumers surveyed said the recession has caused them to become more resourceful, with 87 percent reporting that they’re looking at spending categories to see where they can save.<sup>3</sup> This frugality has naturally spilled over into electricity consumption. According to the study, 68 percent of consumers said they took extra steps to reduce their electric bills due to the recession. And even if the economy rebounds, 95 percent don’t intend to increase their electricity usage. Whether due to greater built-in efficiency or greater consumer resourcefulness—or both—the likelihood appears to be increasing that at least some of the recent demand declines could be permanent.</p>
<p>These adverse factors and the uncertainty around federal tax policy are certainly enough to give renewable proponents pause, but they likely aren’t sufficient to stop the advancing train of deals aimed at producing cleaner energy at palatable rates of return. Larger forces are at work. Several broad policy and market conditions, along with specific drivers within the subsectors of wind, solar and biomass, appear to have the momentum needed to overcome these drags on the M&amp;A market. Propelled by collective strength in these areas, M&amp;A activity is likely to increase over the next few years.</p>
<p>Current trends within energy markets bode well for renewable activity. Among them is pressure for power producers to move away from coal-fired generation. Recently, the Environmental Protection Agency (EPA) has been flexing its muscles under the Clean Air Act to control air quality through a series of rule makings. The Cross-State Air Pollution Rule—issued in July 2011 and recently stayed by a federal court—requires utilities to cut sulfur dioxide (SO<sub>2</sub>) and nitrogen oxide (NOx) emissions that drift into other states. The EPA also issued mercury and air toxics standards, which seek to put national limits on mercury, acid gases, and other toxic pollution from power plants. Even while the legality of these rulemakings is being challenged by several states and power and utilities companies, numerous other proposed regulations are queuing up at the local, state and federal levels, concerning not only the environmental impacts of electricity generation but also of oil and gas production.</p>
<p>Whatever form and timing the final regulations take, a clean air movement is underway that likely will cause utilities and independent power producers (IPP) to retire older coal plants and defer building new ones—thus boosting the demand for replacement power capacity, some of which will be renewables. Meanwhile, as coal-fired generation comes under greater scrutiny, the remaining traditional fuel for zero-emissions power generation—uranium—has incurred a severe setback. The development of nuclear energy in the U.S. and Europe has been slowed in the aftermath of the nuclear disaster at Japan’s Fukushima plant. Additionally, Germany’s recent announcement that it plans to phase out all nuclear power by 2022 gave new impetus to the argument for alternative energy.</p>
<p>“But what about natural gas?” some might ask. Abundant, cheap, and emitting about half the CO<sub>2</sub> of coal, natural gas seems to be a no-brainer for the next round of generation construction in the U.S. However, as electric power companies consider options for their generation portfolios, the specter of gas price volatility likely will return. Current low natural gas prices are putting pressure on PPAs and discouraging renewables deals, but over the long-run—remembering that fossil power plants have life spans of 30 years or more—these prices likely will rise due to increased demand, liquefied natural gas (LNG) exports, and higher production costs, among other dynamics. While natural gas likely will be a big part of the future fuel mix, utilities are giving careful thought to balancing their generation portfolios to weather many different types of market scenarios. Through this process, some are discovering that natural gas and renewables are a good match. Natural gas and biomass, for instance, are assuming a new role as a counterbalance to the variability of renewables as power producers begin to co-locate and integrate these types of plants with solar and wind installations.</p>
<p>While federal tax policy is uncertain at best, and at worst seems detrimental to renewable development, other types of government policies have stepped in to fill the void. Chief among them are state RPS policies. These mandates support long-term demand for renewable energy, making investment in the sector attractive. The strength of RPS has been a key factor in regional deal activity and will continue to be going forward. 39 states plus the District of Columbia already have renewable portfolio requirements of some sort, and many are expanding their RPS provisions to include emerging forms of renewable power, such as small hydro and tidal.<sup>4</sup></p>
<p>Feed-in-tariffs (FIT) represent another policy shift that could spur renewable development. A few states, such as California, Hawaii and Vermont, along with several municipalities, have started implementing FITs, which offer developers a fixed price for the renewable power they produce. This policy, which is similar to the European model, will drive more development since it provides increased certainty of prices, without the cost or complications of negotiating a PPA. This likely will lead to more M&amp;A, given increased development and a greater ability to leverage the stable financial benefits.</p>
<p>Many state governments have rationalized their regulatory approval processes as well. Simpler approval processes lead to greater certainty in planning and fewer costly delays, ultimately benefitting the renewables market.</p>
<h4>Game-Changers Emerging</h4>
<p>Other technological innovations could remove additional barriers to renewable development. Because of the intermittency of wind and solar, utilities can’t rely on these sources to meet baseload requirements. This limitation, along with inadequate transmission capabilities, constrains M&amp;A deals, particularly interstate ones. Advances in large-scale energy storage would remove this constraint, inviting all sorts of transactions as power producers and utilities redefine their operational boundaries and rebalance their generation portfolios. Notably, such advances might be closer than we think. For example, AES built a 98-MW wind farm equipped with 32 MW of battery storage in West Virginia; Duke Energy is in the process of adding 36 MW of battery storage to its 153-MW Notrees wind power project in West Texas; and Hawaiian Electric recently added battery storage to its solar photovoltaic project on the island of Lanai.<sup>5</sup></p>
<p>Ironically, one of the most powerful game-changers on the horizon is largely being overlooked: generational change. Younger people are demanding cleaner, greener sources of energy for their own consumption as well as holding their employers to higher standards regarding sustainability and environmental stewardship. According to a recent study by Johnson Controls on global workplace innovation, members of Generation Y, defined as people between the ages of 18 and 25, are demanding a greener work environment, with 96 percent reporting that they want an “environmentally aware” workplace. More specifically, 70.3 percent said that the workplace should have recycling bins, 52.7 percent said stand-by modes or devices are musts for all electrical equipment, and 47 percent said solar panels should be on site.<sup>6</sup></p>
<p>In addition to broad policy and market conditions, several factors within the sub-sectors of wind, solar and biomass also point to continuing deal volume.</p>
<p>• <i>Solar Rise:</i> In the solar arena, the need for diversification and government incentives are primary M&amp;A drivers. Diversification is important because some solar companies need to build capabilities across the value chain to compete in a small and fragmented market. Company strategies to become one-stop solution providers have been, and will continue to be, a boon to M&amp;A activity. Government incentives too are aligned to support continued solar development. Over the past few years, the ITC and cash grants helped small players enter the capital-intensive solar industry. This led to a ripe M&amp;A market, as large developers were able to acquire a mature pipeline of projects from smaller entrants. It also allowed a broader class of investors to use the tax incentives and participate in the industry. Today, a continuation of the ITC until 2016 is supporting further M&amp;A activity. These government incentives will remain an important enabler until solar reaches grid parity.</p>
<p>State RPS and solar-specific mandates are also causing utilities to emerge both as prominent buyers of solar capacity and developers of new projects through JVs. New trends such as utility-scale solar and participation from non-energy companies will further drive M&amp;A, as will the entrance of foreign companies that are looking to purchase U.S. assets in an effort to compensate for weak demand elsewhere.</p>
<p>Smaller IPPs likely will seek to diversify project portfolios and grow quickly while eliminating competitors in the market. Utilities probably will eye development projects in advanced stages or newly built ones in an effort to pursue growth opportunities and to assist with RPS compliance—rather than just using PPAs. In some cases, utilities will look to acquire assets through a non-regulated business to fulfill a broader growth strategy, and they likely will seek JVs with developers to install rooftop solar panels. Financial institutions are expected to focus primarily on assets that are nearing the point where they’ll begin generating revenue due to a highly competitive and maturing market. Foreign investors most likely will continue looking to the U.S. as a means of expanding their global footprints and broadening their platforms. Finally, infrastructure investors probably will look to solar for solid and stable returns from operating projects.</p>
<p>• <i>Wind Options:</i> Wind projects and deals are being driven by the federal PTC, but it’s set to expire in December 2012. Uncertainty over extensions of this incentive will affect deal activity in the near-term as will low natural gas prices. The abundance of cheap domestic natural gas already suppressed wind development in 2010, prior to its resurgence in 2011, driven by the expiration of the Treasury cash grants. U.S. Henry Hub benchmark gas prices ranged from $3 to $5 per MMBtu for most of 2010 and 2011, far below the $13 peak of 2008.<sup>7</sup> Wind project returns are falling as well, since utilities are now willing to pay less for PPAs in light of competitive natural gas options. This will affect the number of wind projects coming online and reduce the amount of transactions.</p>
<p>While this sounds like a lot of bad news for wind developers, other factors likely will offset some of these drawbacks, possibly even tipping the balance the other way. For instance, government policy in the form of RPS mandates has increased deal activity from utilities, which are becoming major buyers of wind assets. Meanwhile, a proposed ITC for offshore wind and tougher EPA-sanctioned pollution controls could spur a move toward renewables and possibly boost deals, if they come to pass. Even current low natural gas prices could be a driver for wind energy, as companies look at renewable M&amp;A for longer-term price stability and portfolio rebalancing. Wind projects have another thing going for them: They can easily access capital since the technology is mature. Private investment has matched government support, making projects economically viable and serving as a moderate driver for M&amp;A. In 2010, the U.S. was the global leader in wind project funding activity with 18 deals worth $3.8 billion and 10 debt funding deals worth $940 million.<sup>8</sup></p>
<p>IPPs probably will seek generation-stage wind projects or those under construction to access capital, a need that’s being exacerbated by the end of Treasury cash grants and a trend toward larger projects. Utilities likely will pursue operating projects due to the need for an increased share of green energy in the portfolio in light of stricter RPS mandates. Financial institutions are expected to focus primarily on assets that are nearing revenue generation, but outside of that, they likely will remain cautious due to the impending PTC expiration. However, if PTCs are extended beyond 2012 or the proposed investment tax credit for offshore wind is passed, these investors likely will show renewed interest in the subsector. Finally, as with solar, infrastructure investors probably will look for solid and stable returns from operating projects. On a broader level, the impending PTC expiration likely will result in development pipelines or early stage development projects getting reduced valuations for M&amp;A or possibly requiring earn-out structures as a method to ascribe value to such assets if included in a portfolio.</p>
<p>• <i>Biomass Growth:</i> In the biomass sector, the need to develop efficient technologies to achieve favorable economics will drive future M&amp;A activity. At present, many biomass producers have technology gaps, which they will try to fill by acquiring companies or entering into JVs. The most successful in this subsector will find ways to improve capacity factors, diversify feedstocks, and co-fire with coal and natural gas to enhance reliability and reduce costs.</p>
<p>Additionally, improved access to funding and continued government support will attract large companies to invest in the subsector. Power producers who use biomass will continue to gain from renewable-related incentives under the <i>American Recovery and Reinvestment Act</i> and financial assistance for biomass feedstock production and delivery under the USDA’s Biomass Crop Assistance Program. State RPS requirements also are likely to drive demand. The volume of future deals, however, will depend largely on the EPA’s decision about whether biomass should comply with greenhouse gas permitting requirements. Currently, the EPA has deferred this decision until January 2014.<sup>9 </sup></p>
<p>IPPs likely will pursue JVs with companies associated with paper and wood-based products to provide easy access to raw materials for running biomass plants. They also will target smaller IPPs that provide geographic diversification. Utilities probably will seek JVs for new project development with co-firing capabilities to reduce reliance on a single source of generation. Financial investors likely will seek projects that are in the late stages of development that have received government approval, viewing biomass as a growing industry that can offer high return on investment and substantial growth.</p>
<h4>Green Shift</h4>
<p>Overall, both broad market conditions and subsector drivers suggest that utilities will remain very active in renewable M&amp;A, driven by a need to meet RPS, balance generation portfolios, and grow in the absence of organic opportunities. Much of this activity will center on acquiring generation projects and development pipelines—most likely with the exception of wind—as well as partnering with other investors to spread out exposure to individual projects and in some cases divesting renewable projects that no longer meet their criteria.</p>
<p>In the near-term, utilities are likely to continue investing in renewables through unregulated subsidiaries. For example, Allete recently formed an unregulated generation subsidiary to develop clean energy projects. In general, utilities likely will favor deal activity in generation-stage projects and will negotiate PPAs for development-stage projects as a risk-mitigating strategy and to meet state RPS. They’re also likely to seek out JVs with developers on larger projects in order to take advantage of their development pipelines.</p>
<p>From a sub-sector perspective, wind has traditionally dominated utility deals; however, the amount of solar deals has surged since 2010, with an increase in the number of utility-scale projects due to falling panel prices and government incentives. Given current tax policies and consolidation among solar manufacturers, this trend likely will continue. Biomass has gained utility interest recently, although feedstock supply issues are still a concern. Deals are expected to increase in light of biomass’s exemption for emissions caps under the EPA Prevention of Significant Deterioration and Title V Programs for the next three years <i>(see Figure 4).</i> While their focus has been primarily on acquiring renewable generation assets, utilities might divest some renewable projects in the next couple of years due to lower energy prices from other sources or to shift their portfolio mix toward improved technologies. This shift can be viewed as the natural course in a rapidly maturing marketplace.</p>
<p>All things considered, the renewable sector is poised to continue generating clean, reliable electricity as well as acceptable returns for investors. Despite the death of the Treasury cash grants, the renewable power sector is as resilient as its name implies. M&amp;A activity likely will continue over the next few years as new innovations spur growth and as mature portions of the industry consolidate.</p>
<h4>Endnotes:</h4>
<p>1. Herold Transactions Database, deals from Jan. 1, 2007 through Dec. 7, 2011, IHS Inc.</p>
<p>2. <i>Annual Energy Outlook 2011</i>, U.S. Energy Information Administration</p>
<p>3. <i>Deloitte reSources 2011 Study</i></p>
<p>4. <a href="http://www.c2es.org/what_s_being_done/in_the_states/rps.cfm" target="_blank">Center for Climate and Energy Solutions</a>.</p>
<p>5. “AES opens largest battery storage project of its kind high atop W.Va. mountain,” <i>SNL News Feed</i>, Nov. 1, 2011; “Sandia Lab: Solar PV installation no threat to Lanai microgrid,” <i>SNL News Feed</i>, Jan. 20, 2012; “<a href="http://www.duke-energy.com/" target="_blank">Duke Energy to Deploy Energy Storage Technology at Texas Wind Farm</a>,” April 14, 2011.</p>
<p>6. <i>Generation Y and the Workplace Annual Report 2010</i>, Global WorkPlace Innovation, Johnson Controls, accessed via <a href="http://www.Oxygenz.com" target="_blank">www.Oxygenz.com</a></p>
<p>7. <a href="http://www.eia.gov/naturalgas" target="_blank">Natural Gas Weekly Update</a><i>,</i> Energy Information Administration.</p>
<p>8. <i>2010 Wind Funding and M&amp;A Report,</i> Mercom Capital Group</p>
<p>9. “EPA Defers GHG Permitting Requirements for Biomass Industries,” <i>Renewable Energy World,</i> Jan. 19, 2011.</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
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<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">Who&#039;s Zoomin&#039; Who?</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter--><p>An interesting part of the M&amp;A picture is the diversity of players active in the market. Some, of course, are the usual suspects. Venture capitalists (VC) have been active over the last five years and still are, despite bankruptcies and incentive expiration. VC funding, however, has been trending away from renewable generation assets to instead focus on clean-tech development and the manufacturing end of the renewables industry. Meanwhile, independent power producers (IPP) increasingly have been turning to M&amp;A, particularly in the wind and biomass subsectors, as they explore alternate financing channels and consolidation opportunities.</p><p>Other likely players are U.S. utilities. Some have been increasing renewable deal activity on the regulated side in an effort to meet state renewable standards as well as their overall supply needs. On the unregulated side, some are pursuing renewable M&amp;A through their generation subsidiaries as part of their overall growth strategies. In either case, U.S. utilities often have a competitive edge over other types of investors since they have the tax capacity needed to fully leverage government tax incentives.</p><p>Private equity investors also have played a major role in spurring renewable M&amp;A activity, but this involvement has occurred in two waves. The first focused on acquiring developers, such as EverPower, First Wind, Noble Environmental Power, Element Power, and Horizon—now EDP Renewables. This approach appears to have phased out as the second wave, marked by investments from infrastructure funds, has gained momentum. Fund investments became popular after the Treasury cash grants eliminated the need to have taxable income in order to leverage the production tax credits. Over the last few years, managers of domestic and foreign infrastructure funds have waded into the U.S. wind and solar markets in search of predictable returns for their dividend-focused investors.</p><p>A noteworthy development is the large influx of foreign investors that have been entering the space. Some of these investors are pure-play financials, such as large Japanese trading companies that are seeking stable returns and a means to offset their U.S. tax liabilities. Others are much more strategic. Acquisitions by European and Asian investors have been on the rise. Companies such as Gamesa, Goldwind, EDP, Iberdrola, EDF, and E.ON have been active in the U.S. wind market. Similarly, Acciona, EDF, Abengoa, and LDK Solar are foreign players operating in the U.S solar market. Much of this activity was once again encouraged by the Treasury cash grants, which eliminated the need for a U.S. tax appetite. Moving forward, however, another motive for these players likely will come to the forefront: the need to find opportunities for growth and diversification beyond their own markets. Chinese energy companies, for instance, are interested in Western expansion and diversification, and notably are willing to deploy capital without immediate cash return, making it feasible for them to line up behind tax equity partners. Chinese equipment manufacturers are also looking to find and source development projects so they can deploy their own technologies and expand their global footprint.</p><p>Expansion into the U.S. market also gives foreign strategic investors, such as European-owned utilities, the chance to leverage their prior experiences in developing renewables within their relatively mature home territories. This experience, when applied to the still-growing U.S. market, potentially can give them a competitive advantage.–<span><span class="bolditalic">BB and MM</span></span></p></div></div></div> </div>
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Sun, 01 Apr 2012 04:00:00 +0000puradmin13398 at http://www.fortnightly.comCommerce Clause Conflicthttp://www.fortnightly.com/fortnightly/2010/12/commerce-clause-conflict
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>In-state green mandates face Constitutional challenges.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>By Richard Lehfeldt, Woody N. Peterson, and David T. Schur</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Richard Lehfeldt</b> (<a href="mailto:lehfeldtr@dicksteinshapiro.com">lehfeldtr@dicksteinshapiro.com</a>) is a partner in Dickstein Shapiro LLP’s energy practice. <b>Woody N. Peterson</b> (<a href="mailto:petersonw@dicksteinshapiro.com">petersonw@dicksteinshapiro.com</a>) is a partner in the firm’s business litigation practice, and <b>David T. Schur</b> is a research attorney with the firm.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - December 2010</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Massachusetts wanted renewable power—lots of it, and sooner rather than later.</p>
<p>So it established cutting-edge energy efficiency standards. It enacted tax incentives for qualifying biofuels and low-carbon fuels. It adopted California’s vehicle standards—the most stringent in the nation. It developed, in conjunction with other New England states, a climate change action plan. It joined the Regional Greenhouse Gas Initiative (RGGI), a multi-state emission cap-and-trade program. It established industrial emission targets. It devised an aggressive renewable portfolio standard (RPS) requiring its utilities to use significantly more renewable power to meet load requirements.</p>
<p>So far, so good—these efforts were praised by both the environmental community and the burgeoning alternative energy and energy efficiency industries.</p>
<p>But then Massachusetts enacted the Green Communities Act (GCA) in 2008 to foster the development of new renewable power plants within the Commonwealth.<sup>1 </sup>One of the ways the GCA tried to do this, in Section 83, was to require Massachusetts electric distribution companies to enter into long-term power purchase agreements (PPAs) with renewable power companies located “within the jurisdictional boundaries of the Commonwealth.”</p>
<p>This latest Massachusetts initiative didn’t trigger kudos, but instead condemnation in the form of a lawsuit by TransCanada Power Marketing Ltd. An established competitive power company with numerous renewable power projects either completed or under development throughout New England,<sup>2</sup> TransCanada filed a lawsuit attacking what TransCanada called Massachusetts’ “home-grown” preference in GCA Section 83.<sup>3</sup> TransCanada’s prime target was the Commonwealth’s 2010 request for proposals (RFP) that only allowed the submission of proposals from projects located in Massachusetts. Trans-Canada says the GCA discriminates against out-of-state renewable generation facilities that are physically and functionally indistinguishable from in-state facilities, in violation of the Commerce Clause of the United States Constitution, under the so-called Dormant Commerce Clause doctrine.<sup>4</sup></p>
<p>The Massachusetts litigation brings into sharp focus a potential conflict between states seeking to maximize development of in-state renewable power resources and the legitimate objectives of the competitive power industry, which has been responsible for the development and operation of most of the nation’s renewable power resources to date. Can these two legitimate but conflicting objectives be harmonized?</p>
<p>Considering the types of incentives currently available to renewable power development, and the Dormant Commerce doctrinal law against that landscape, some answers emerge that might allow states to reduce the tension between these two sets of legitimate objectives—and prevent a Constitutional challenge.</p>
<h4>Renewable Power Growth</h4>
<p>Development of most electric power resources has slowed in recent years, but not renewable power. That resource, long just a figment of science fiction writers’ and idealists’ imaginations, today is a welcome reality. In 2009, in the midst of the worst economic climate since the Great Depression, the American wind industry installed nearly 10,000 MW of new generating capacity.<sup>5</sup> Renewable power will continue to play—and some would say must continue to play—a leading role in America’s energy and climate policies.</p>
<p>Important and essential as that role will be, filling it will be neither easy nor cheap. The electric power sector is the most capital-intensive industry in the world, and renewable power plants are expensive to construct. Although the cost of renewable power plants should continue to fall in absolute terms as more plants are built—and will fall also in relative terms once carbon costs are included in the nation’s resource choices—the cost of building a utility-scale renewable plant today typically ranges from hundreds of millions to billions of dollars.</p>
<p>On top of that, renewable power development today involves complex, confusing, and overlapping skeins of preferences, tax incentives, and mandates. At the federal level, these include the investment tax credit, the production tax credit, various grant and loan guarantee opportunities, the regulatory exemptions available since 1978 under PURPA,<sup>6</sup> and the steroidal benefits provided by the Stimulus Act,<sup>7</sup> which are time-limited but provide in some instances cash-equivalent Treasury grants for up to 30 percent of the capital cost of a renewable power project.</p>
<p>Twenty-nine states and the District of Columbia each have adopted an RPS that mandates the development of renewable power resources. The 30 pieces of this regulatory puzzle have only one thing in common: a legal requirement that jurisdictional utilities within the state have a certain percentage of renewable power within their generation portfolios by a date or dates certain. Everything else in the programs differs dramatically, and in every conceivable way. For example:</p>
<p>• What resources qualify as “renewable” under state law;</p>
<p>• What portfolio percentages are mandated, and by when;</p>
<p>• Whether there are “set-asides” for certain favored technologies;</p>
<p>• Who (as between the utilities themselves and third-party providers) will be expected to build these resources;</p>
<p>• The compliance and enforcement regimes established to ensure adherence to the mandates; and</p>
<p>• How to deal with cross-border sales of renewable power—and the renewable energy credits associated with renewable power resources.</p>
<p>The U.S. Congress has tried, and to date failed, to enact a federal RPS law that would end this balkanized regime and replace it with a unitary, national template.</p>
<p>States have begun to address the material costs associated with these requirements—including the necessary ancillary capital expenditures, such as new transmission lines and supplementary generation to balance intermittent resources such as solar and wind power—with the limited arsenal of regulatory and financial tools available to the sector as a whole. With the filing of the TransCanada suit, the question has become whether the Dormant Commerce Clause might limit the states’ ability to utilize some of these tools.</p>
<h4>The Dormant Commerce Clause</h4>
<p>As more than one court has noted with exasperation, “[h]armonizing the guidance set out in the Supreme Court’s many dormant Commerce Clause opinions is not a simple task.”<sup>8</sup></p>
<p>A few principles, however, can readily be derived. The threshold question in any Dormant Commerce Clause inquiry is: Does the law discriminate? In this context, “discrimination simply means differential treatment of in-state and out-of-state economic interests that benefits the former and burdens the latter.”<sup>9</sup> Examples of state laws that discriminate are those that prohibit out-of-state direct shipment of wine into the state, but allow in-state shipments,<sup>10</sup> grant tax credits only for ethanol produced in a particular state,<sup>11</sup> and require electric utilities to use coal produced in that state.<sup>12 </sup></p>
<p>If the law “discriminates” within the meaning of the Dormant Commerce Clause, then it’s subject to strict scrutiny and will be upheld only if it “advances a legitimate local purpose that cannot be adequately served by reasonable nondiscriminatory alternatives.”<sup>13</sup> This is a difficult standard to satisfy. Indeed, “[s]tate laws that discriminate against interstate commerce face a virtually <i>per se</i> rule of invalidity.”<sup>14</sup> Facially discriminatory laws are routinely struck down, and generally have been upheld only in the very narrow quarantine context, where the very movement of articles in interstate commerce risks imminent contamination and disease.<sup>15 </sup></p>
<p>If there is no “discrimination,” however, then the much more forgiving balancing test of <i>Pike v. Bruce Church, Inc</i>.<sup>16</sup> applies. The <i>Pike</i> test is “reserved for laws directed to legitimate local concerns, with effects upon interstate commerce that are only incidental.”<sup>17</sup> Under this test, a court will uphold a nondiscriminatory statute “unless the burden imposed on [interstate] commerce is clearly excessive in relation to the putative local benefits.”<sup>18</sup> State laws frequently survive <i>Pike</i> scrutiny,<sup>19</sup> though not always, as in <i>Pike</i> itself.<sup>20 </sup></p>
<p>There are two exceptions to these principles by which a seemingly discriminatory law can pass Dormant Commerce Clause muster. The first is the “market participant” exception. If the state is acting as a “market participant” rather than a regulator, discrimination is permissible.<sup>21</sup> Thus, for example, a state-owned cement plant can give preference to in-state customers without running afoul of the Dormant Commerce Clause.<sup>22</sup> The second is the “public entity” exception, whereby discrimination is permissible if it favors public entities while treating in-state and out-of-state private entities the same.<sup>23</sup></p>
<p>Harmonizing the Supreme Court’s Dormant Commerce Clause guidance is difficult enough in traditional contexts. It is even more so in the context of renewable power plants.</p>
<p>At first glance, the analysis seems straightforward enough: a power plant is a factory—a big, expensive one, but a factory all the same—that from the outside looks much like any conventional factory.</p>
<p>A power plant, like all factories, is a large-scale economic engine. Factories create construction jobs, permanent jobs, multiplier-effect jobs that ripple through a local economy, and long-term tax revenues. State and local governments must either embrace or tolerate the development of factories in order for them to get built. Indeed, public entities often go even farther and compete against one another, utilizing a mix of grants, tax holidays, and other incentives to persuade the owners of auto plants, baseball parks, and green technology factories to build them in their state. None of these economic incentives would appear to implicate the Commerce Clause. The decision by State A to allow construction of a factory in State A doesn’t give rise to a complaint under the Commerce Clause from State B for failure to construct the factory in State B; a factory has to be built somewhere, and the ultimate choice of a site doesn’t, on its own, interfere with interstate commerce.</p>
<p>The Dormant Commerce Clause doctrine is potentially implicated, however, with regard to the plant’s products. If a power plant is a factory, its product is electricity. Electricity is in many ways a commodity like tangible products such as milk, phosphates, and alcohol. It flows in interstate commerce pursuant to the laws of physics, regardless of its buyers’ and sellers’ intentions, regulatory compacts, or contractual arrangements. While the end product (electrons) is fungible, there’s considerable variety in the sources of that end product (coal, geothermal, etc.). Power plants, whether developed under traditional utility cost-of-service ratemaking, or through long-term PPAs between a utility and a developer, involve the dedication of resources to serve a load, but the plant’s electrons can be sold and resold, at wholesale or in some instances across state lines, into a regional pool, or even across regions, so long as transmission capacity and economics are capable of supporting the sale.</p>
<p>Finally, most power plants have significant byproducts, including solid waste and air emissions. Most of these byproducts are subject to comprehensive regulatory regimes administered by the U.S. Environmental Protection Agency, with much of that authority delegated to the states for implementation. Indeed, a major aspect of states’ quest for renewable power is the desire to avoid or displace power plants with significant emission profiles (<i>e.g.</i>, coal) and to replace them with resources that have minimal emissions (<i>e.g.</i>, wind or solar facilities). The Commonwealth of Massachusetts and numerous other states have indicated clearly that these emissions are a critical component of their resource decisions, <i>i.e</i>., that it matters to them what fuel creates their electricity. That public policy choice—reflected, as noted, throughout Massachusetts’ energy and environmental policy—suggests a colorable state defense against a dormant Commerce Clause attack, based on “a legitimate local purpose that cannot be adequately served by reasonable nondiscriminatory alternatives.”<sup>24 </sup></p>
<p>Programs that involve building in-state power plants can thus simultaneously trigger scrutiny under two aspects of Dormant Commerce Clause case law: state programs that provide significant benefits to develop in-state resources or to keep such resources in-state <i>(see New England Power Co. v. New Hampshire, 455 U.S. 331, 344 (1982), striking down state law prohibiting out-of-state export of hydroelectric power)</i>, and state programs that seek to keep out articles of commerce that the state wants no part of, such as garbage <i>(see Philadelphia v. New Jersey, 437 U.S. 617, 628 (1978), striking down state law prohibiting importing trash collected out-of-state)</i>.</p>
<h4>Harmonizing Objectives</h4>
<p>States haven’t waited for Congress to enact a federal RPS standard. Those that have already established their own RPS programs have set their sights on a major shift in the fuels America uses to make its electricity. That shift will require new infrastructure, which will in turn require significant capital and involve significant financial risk for companies that want to build it. And companies will have to finance these projects at a time of unprecedented capital constraint.</p>
<p>The electricity industry has existed for more than a century, but stills relies chiefly on only two financing mechanisms to pay for its larger infrastructure needs: utility rate-basing and long-term PPAs between a power project and a load-serving utility that provide the foundation for project financing. The challenged GCA Section 83 relies on the latter. Section 83 requires in-state regulated utilities—the only ones over which the Commonwealth has legal authority—to buy their renewable power only from in-state facilities under long-term PPAs.</p>
<p>Under current economic conditions, executed PPAs are necessary for sponsors to obtain project financing of non-utility facilities. Commerce Clause attacks on RFPs for new renewable power resources accordingly pose a potential threat to states’ ability to meet their renewable portfolio objectives, to make resource decisions outside the purview of the organized markets, to participate proactively in environmental markets such as RGGI, and to develop in-state assets that are ready to compete in the emerging green economy. Without executed PPAs capable of defeating Commerce Clause attacks, these resources, if developed at all, will instead be developed outside the competitive process, most likely by traditional utilities. That outcome, ironically, would be the exact opposite of what Trans-Canada seeks in its lawsuit against Massachusetts.<sup>25</sup></p>
<p>What, then, can a state do to inoculate itself against such attacks? To begin with, the state should approach the development of these power plants much as it approaches more traditional economic development: by making explicit at the outset the incentives it’s offering to convince developers to build facilities in the state. The opportunity to enter into a long-term PPA should be one of the benefits offered to successful bidders as part of the state’s development initiative, not the starting point. As noted above, the state is on its firmest ground, and least vulnerable to Commerce Clause assault, when approaching economic development in this way. Massachusetts is by no means the only jurisdiction that views the development of green businesses within its borders as not just an environmental objective, but a business opportunity that the state can make attractive, if not impossible to resist, by offering financial incentives to a company if it chooses to build the plant within its borders.</p>
<p>Second, the state should highlight the specific reasons why it seeks to develop a particular resource at a unique site. For example, from a Commerce Clause vantage point, it’s wholly appropriate for a state to take steps to solicit companies to develop power plants at either brownfield sites within its borders, or offshore wind resources in the waters off its coastline within its jurisdiction. So long as these objectives are explicit and transparent, the state should be able to defend against arguments such as those made by TransCanada that there is no functional difference between a power plant in an adjoining state, and a power plant that Massachusetts is seeking to develop within the Commonwealth.</p>
<p>Finally, the state, in encouraging in-state development, should make explicit the environmental objectives and benefits of clean in-state generation. While electrons are fungible, the byproducts of the power plant factory (solid waste, air emissions, etc.) are not. A state that seeks new in-state renewable power plants may increase its reserve margins, improve its air quality, displace fossil-fuel based generation, avoid transmission congestion charges that may apply, and may also avoid or defer the need to build new transmission lines. All of these are defensible state policy objectives that can serve to defend against dormant Commerce Clause attacks.</p>
<p>The nation’s emerging commitment to renewable power is in its early stages. With or without a national consensus on climate change, a resource shift of this magnitude hits many of the major fault lines in the nation’s complicated energy policy: fuel choice, the costs and benefits of environmental improvement, the tension between federal and state authority over these decisions, and the unresolved national debate between a monopoly regulatory model and a competitive alternative. The TransCanada litigation is but one forum to begin to address issues that are more typically taken up by legislatures. Despite the murky judicial history of the Dormant Commerce Clause doctrine, there should be room for the court to resolve the collision in this suit between two meritorious social objectives: environmental improvement and fair competition.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. 2008 Mass. Acts c.169.</p>
<p> </p>
<p>2. <i>TransCanada Power Marketing Ltd. v. Bowles</i>, Civil Action No. 4:10-CV-40070-FDS (D Mass., filed Apr. 16, 2010) (“Complaint”).</p>
<p>3. Complaint at p. 15.</p>
<p>4. The Commerce Clause gives Congress the power “to regulate commerce . . . among the several States.” U.S. Const. art. I, § 8, cl. 3. The “Dormant Commerce Clause” doctrine is a judicially constructed negative corollary of the Commerce Clause that essentially “prevents a State from jeopardizing the welfare of the Nation as a whole by placing burdens on the flow of commerce across its borders that commerce wholly within those borders would not bear.” <i>Am. Trucking Ass’ns v. Michigan Pub. Serv. Comm’n, 545 U.S. 429, 433 (2005) (quoting Oaklahoma Tax Comm’n v. Jefferson Lines, Inc., 514 U.S. 175, 180</i> (1995)).</p>
<p>5. American Wind Energy Association Year End 2009 Market Report (Jan. 2010)</p>
<p>6. The Public Utility Regulatory Policies Act of 1978, 16 U.S.C. §§ 2601-2645.</p>
<p>7. The American Recovery and Reinvestment Act of 2009, Pub. L. No. 111-5, 123 Stat. 115 (2009).</p>
<p>8. <i>Am. Bus Ass’n. v. District of Columbia</i>, [2 A.3d 203]; [2010 D.C. App. LEXIS 493] at *25 (D.C. 2010).</p>
<p>9. <i>United Haulers Ass’n, Inc. v. Oneida-Herkimer Solid Waste Mgmt. Auth.,</i> 550 U.S. 330 (2007) (internal quotation marks omitted).</p>
<p>10. <i>See Granholm v. Heald</i>, 544 U.S. 460 (2005).</p>
<p>11. <i>See New Energy Co. of Indiana v. Limbach</i>, 486 U.S. 269 (1988).</p>
<p>12. <i>See Wyoming v. Oklahoma</i>, 502 U.S. 437 (1992).</p>
<p>13. [Granholm, 544 U.S. at 489.]</p>
<p>14. <i>Id.</i> at 476 (internal quotation marks omitted).</p>
<p>15. <i>See City of Philadelphia v. New Jersey</i>, 437 U.S. 617, 628-629 (1978) (“[C]ertain quarantine laws have not been considered forbidden protectionist measures, even though they were directed against out-of-state commerce… [T]hose quarantine laws banned the importation of articles such as diseased livestock that required destruction as soon as possible because their very movement risked contagion and other evils. Those laws thus did not discriminate against interstate commerce as such, but simply prevented traffic in noxious articles, whatever their origin.”) <i>(citing Asbell v. Kansas, 209 U.S. 251 (1908), Reid v. Colorado, 187 U.S. 137 (1902), Bowman v. Chicago &amp; N. W. Ry. Co., 125 U.S. 465</i> (1888)).</p>
<p>16. 397 U.S. 137 (1970).</p>
<p>17. <i>United Haulers</i>, 550 U.S. at 346 (internal quotation marks omitted).</p>
<p>18. <i> Id.</i> (internal quotation marks omitted).</p>
<p>19. <i>See, e.g., Id. at 346-47;</i> ][ <i> Nw. Cent. Pipeline Corp. v. State Corporation Comm’n of Kansas</i>, 489 U.S. 493, 525- 526 (1989) (upholding under<i> Pike</i> a state regulation which provided that the right to extract natural gas would be forfeited if production was delayed too long); <i>Minnesota v. Clover Leaf Creamery Co.</i>, 449 U.S. 456, 472-474 (1981) (upholding under <i>Pike</i> a state law prohibiting sale of milk in certain plastic bottles).</p>
<p>20. <i>See Pike</i>, 397 U.S. at 146 (striking down state law that required all state-grown cantaloupes to be packaged within state prior to export).</p>
<p>21. <i>See generally Department of Revenue of Kentucky v. Davis</i>, 553 U.S. 328 (2008) (“Some cases run a different course, however, and an exception covers States that go beyond regulation and themselves participat[e] in the market so as to exercis[e] the right to favor [their] own citizens over others. . . . This market-participant exception reflects a basic distinction ... between States as market participants and States as market regulators,. . . [t]here [being] no indication of a constitutional plan to limit the ability of the States themselves to operate freely in the free market.”) (internal quotation marks omitted) (alterations in <i>Davis</i>).</p>
<p>22. <i>Reeves, Inc. v. Stake</i>, 447 U.S. 429, 436-46 (1980).</p>
<p>23. <i>See, e.g., United Haulers</i>, 550 U.S. at 343 (upholding “flow control” ordinance requiring trash haulers to deliver solid waste to a processing plant owned and operated by a public authority); <i>Davis</i>, 553 U.S. at 343 (upholding state law which provided tax exemption for bonds issued by the state, but not for those issues by other states).</p>
<p>24. <i>Granholm, supra</i>, 544 U.S. at 489.</p>
<p>25. If, as TransCanada has argued, Massachusetts’ decision to award PPAs only to in-state resources is Constitutionally suspect, it’s unclear why the numerous state PUC decisions over more than a century awarding to franchised utilities the exclusive right to build and rate-base new infrastructure projects isn’t similarly suspect.</p>
<p> </p>
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Wed, 01 Dec 2010 05:00:00 +0000puradmin13563 at http://www.fortnightly.comBack to Businesshttp://www.fortnightly.com/fortnightly/2010/10/back-business
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Utility deals resume after 18 months of austerity.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Michael T. Burr</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Michael T. Burr</b> is <i>Fortnightly’s</i> editor-in-chief. Email him at <a href="mailto:burr@pur.com">burr@pur.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - October 2010</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1010/images/1010-FEA1-figs1-2.jpg" width="1358" height="1256" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1010/images/1010-FEA1-fig3.jpg" width="1362" height="684" alt="" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1010/images/1010-FEA1-fig4.jpg" width="1364" height="723" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1010/images/1010-FEA1-fig5.jpg" width="1512" height="1235" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>There’s a buzz growing in the industry. You hear it at trade shows, where product and service companies are talking about RFPs and contracts again. You hear it at conferences and meetings, where executives and regulators are discussing plans for big-ticket capital expenditures and corporate mergers. And you hear it on Wall Street, where finance executives are managing a steady pace of deals.</p>
<p>The buzz is growing because people see a light at the end of the tunnel. The Great Recession officially ended sometime in 2009, and America seems to be moving forward again.</p>
<p>Arguably, utility companies are the first to know about any big turn in the economy. And indeed, utilities are reporting a substantial uptick in electricity demand—among residential consumers, and even more encouraging, among industrial customers. The U.S. Energy Information Administration reported on September 8 that total U.S. electricity consumption in the first half of 2010 rose 4.2 percent, compared to the first half of 2009, with annual industrial sales projected to increase 6 percent this year.</p>
<p>As a bellwether of economic health, rising energy demand provides strong empirical evidence of a sustainable recovery. This is especially true for growth in commercial and industrial (C&amp;I) consumption. “C&amp;I customers that have made it through the past two years are likely here to stay,” says Frank Napolitano, managing director at RBC Capital Markets.</p>
<p>But of course the buzz isn’t all optimistic. The renewable energy business in particular seems headed for a bust, in an environment of waning political support and tough competition from cheap natural gas-fired generation. But nobody knows whether gas prices will remain low, or whether the shale-gas bubble will burst. And more broadly, overall economic indicators carry an undertone of caution, with muted consumer confidence and stubbornly high unemployment rates.</p>
<p>In the context of this fragile economic environment, the U.S. policy outlook also is shifting in a direction that’s difficult to predict. The November elections might bring some clarity around legislative priorities, but they seem unlikely to eliminate the biggest overhanging policy questions:</p>
<p>• Will companies face tougher federal air emissions regulation? Will the EPA attempt to regulate greenhouse gases (GHG) under its Clean Air Act authority?</p>
<p>• Will Congress allow the Bush-era dividend tax rates to expire?</p>
<p>• Will Congress impose a national renewable energy standard (RES)?</p>
<p>• How will state regulators treat utilities’ plans to increase capital budgets and customer rates?</p>
<p>Even the energy trading and risk management landscape is shifting, with new federal rules on the way <i>(see “<a href="http://www.fortnightly.com/fortnightly/2010/10/energy-trading-under-dodd-frank">Energy Trading Under Dodd-Frank</a>”)</i>.</p>
<p>“In my 24-year career, this sector has never faced more uncertainties or larger moving parts due to politics and the nature of regulation than it faces now,” Napolitano says. “This uncertainty causes utility company management to take a very pragmatic approach. The industry has financial strength and has some choices to make. But most companies won’t choose to bet the farm on any particular strategy.”</p>
<p>A few more quarters of strong economic signals, combined with federal clarity on energy and environmental policy, could allow the industry to move forward more confidently on some key strategic priorities—most notably infrastructure investments and mergers and acquisitions (M&amp;A). In the meantime, utilities are finding easy access to the public capital markets—which we’ll definitely need to keep the buzz going.</p>
<h4>Open Markets</h4>
<p>In the depths of the financial crisis, corporate bond issues virtually stopped as banking institutions circled the wagons. But except for a few anomalous days, when the markets seized up in apparent panic, investment-grade utility companies had little trouble obtaining the debt funds they needed.</p>
<p>“The utility sector has distinguished itself throughout the financial crisis as having access to the capital markets even during the worst of times,” says Tim Kingston, managing director at Goldman Sachs. “That’s unusual compared to other sectors, where access was shut. And now, with historically low interest rates and relatively attractive spreads, issuers are getting some of the lowest all-in rates on borrowing that we’ve ever seen. Many CFOs and financial teams are taking advantage of that to finance their capital needs.”</p>
<p>This continued access bodes very well for the industry’s plans to invest some $1 trillion in infrastructure during the next decade. Low costs of capital will improve the business proposition for the full range of planned construction projects, from gas pipelines to smart-meter rollouts.</p>
<p>Among the various companies in the U.S. electric and gas industry, regulated utilities are the greatest beneficiaries today. Buy-side analysts and investors view the utility sector as a low-risk, cash-flow haven during troubled times. “Investors today are in a defensive position, given the shaky economic backdrop,” says David Nastro, managing director at Morgan Stanley. “The market is rewarding companies with a pure-play, regulated business model.”</p>
<p>As a result, many utilities have been going to market sooner than they otherwise might, to refinance existing debt and also to pre-fund future financing needs. “We see this as an opportunistic grab of low-cost capital,” says James Hempstead, senior vice president with Moody’s. “Companies that were otherwise planning on going into the market later are pre-funding, issuing debt now at attractive rates.”</p>
<p>At this writing, the trend was accelerating, with an unusually large volume of bonds being issued in August—traditionally a slow month on Wall Street—and even more going to market in September <i>(see Figures 1, 2 and 3)</i>.</p>
<p>Banks similarly are welcoming utility industry borrowers.</p>
<p>“Spreads haven’t returned to where they were before the financial crisis, but they’ve tightened a lot,” says Andy Redinger, managing director at KeyBanc Capital Markets. “Banks saw how well utilities did during the financial crisis, and now they want to provide capital to this space.”</p>
<p>In particular, lenders and investors are heartened by utility regulatory structures that have kept companies financially strong through a bad recession. “Coming out of this economic cycle, utilities stayed on an even keel because they had regulatory mechanisms that assured quick recovery of costs,” says John Whitlock, a managing director at Standard &amp; Poor’s. “Tracking mechanisms and fuel-adjustment clauses are very good for credit quality, and have helped to keep utilities from getting stressed.”</p>
<p>The picture is somewhat different for merchant power companies and also hybrid issuers that earn their revenues from a blend of regulated and unregulated businesses. Unexpected volatility in gas prices, combined with sinking electricity demand and a shifting regulatory landscape, put many wholesale operations in a weak position. As such, while investment-grade utilities have been selling bonds with interest-rate spreads below 200 basis points <i>(see Figure 4)</i>, riskier issuers are paying higher premiums—sometimes substantially higher <i>(see Figure 5)</i>.</p>
<p>“Investors are tending to discount non-regulated growth, because of the perceived volatility in cash flow and earnings,” Nastro says.</p>
<p>Even so, quality issuers across the industry are finding a ready appetite on Wall Street for their paper—as well as their stock. “Even with all the speculation and uncertainty, there’s a lot of capital available, in both the debt and equity markets,” says John Lange, head of power investment banking at Barclays Capital. “This might end up being one of the biggest years ever for equity issuance among utility companies. The high-yield markets also are back, after being closed during some periods in the financial crisis. There’s no problem with access to the capital markets.”</p>
<p>Conditions might not remain this favorable for long, however. Today’s uncertainties eventually become tomorrow’s market realities, driving changes in market risks and investor appetites. And with interest rates as low as they are today, money seems unlikely to get much cheaper—which means the current sweet spot can’t last.</p>
<p>“Utilities may face headwinds going into 2011,” Nastro says. “We see the potential for a rising interest-rate environment, and uncertainty around dividend tax rates coming out of Washington, D.C.”</p>
<p>The expiration of Bush-era tax cuts could spur investors out of their defensive posture and into more risky investments—especially if the economy rebounds faster than expected. Thus, the current seller’s market for utility securities might not last too far into 2011—which in part explains the flurry of bond issues that went to market in late summer and early fall.</p>
<p>Companies are getting ready for change.</p>
<h4>Cap-Ex Coming</h4>
<p>Even if costs of capital move upward, Wall Street has shown a consistent willingness to finance utility companies’ needs. That’s a good thing, because those needs seem unlikely to decline any time soon; in fact, capital expense budgets are set to increase next year as companies move forward with a variety of construction programs.</p>
<p>Exactly how much capital spending will rise, and when, depends on a slew of economic and policy questions. But a ballpark figure of $1 trillion through 2020 seems plausible, considering the major cap-ex programs already in the works, and the industry’s recent history. In 2009, for example, the investor-owned power and gas industry in the United States spent about $84 billion—a decline from 2008’s $94 billion, according to the September 2010 <i>Fortnightly 40 Report (See “<a href="http://www.fortnightly.com/fortnightly/2010/09/40-best-energy-companies">The 40 Best Energy Companies</a>,” September 2010 )</i>.</p>
<p>“We’re beginning a construction cycle that’s bigger than any we’ve seen since the 1970s and 1980s,” Redinger says. “It’s kind of a perfect storm. A lot of old coal-fired power plants are quietly being retired, and that capacity needs to be replaced. On top of that, utilities need to satisfy RPS requirements in many states, and the T&amp;D system needs to be upgraded. And at the same time, many utilities have postponed their cap-ex programs to avoid going in for large rate increases during an economic downturn. As soon as the economy starts to take off, utility capital requirements will increase.”</p>
<p>Precisely how companies allocate that spending will depend, at least in part, on trends in regulation and commodity prices. Changes in air-emissions standards and green-energy mandates will affect the number of coal-fired plants that need upgrading or replacing. “Some new EPA rules could add $30 to $40 billion to the industry’s cap-ex budget,” Lange says. “That’s additional spending for pollution control equipment on top of already-planned maintenance cap-ex for the rest of the system.”</p>
<p>Additionally, continued success at domestic shale-gas developments will keep fuel prices low, making other generating options less competitive by comparison.</p>
<p>“Natural gas supply is the big wild card,” Redinger says. “I don’t think anybody expected the amount of gas that’s been discovered over the last 12 to 18 months. Renewable power developers didn’t expect it.”</p>
<p>Cheap gas—and by extension low marginal power prices—have contributed to what seems like an impending bust phase in the renewable energy industry’s perennial boom-bust cycle. Wind projects in particular have been sidelined by low gas prices. At the same time, weakening government support has effectively increased the relative cost of renewable power capacity—and made financing more difficult to find. Specifically, the investment tax credit (ITC) cash-grant provisions of the <i>American Recovery and Reinvestment Act</i> (ARRA) are set to expire at the end of 2010, leaving project owners to compete for a limited supply of tax-equity financing. Morgan Stanley estimates between 20 and 25 projects, totaling 3 GW of capacity, will be canceled for lack of equity funding when the ITC cash-grant expires.</p>
<p>Additionally, some renewable developers face a shortage of long-term debt financing, because most of the institutions in the market provide only short-term construction loans, and not permanent debt.</p>
<p>“The renewable energy market in this country is still in its infancy,” says Anton Cohen, audit principal at accounting firm Reznick Group. “Although we’re seeing some pension funds and other investors come in to make construction loans, small to mid-sized projects are waiting for a permanent financing platform to develop.”</p>
<p>Arguably America’s on-again, off-again federal tax policies have kept the wind and solar industries from maturing. The industry’s predicament is exacerbated by economic hardship; some states, balking at the cost of some renewable energy proposals, are moving to scale back or even suspend their RPS requirements. A ballot measure in California—Proposition 23—would cancel the state’s RPS entirely until unemployment in the state drops from the current 13.2 percent to 5.5 percent for four consecutive quarters. And earlier this year, Connecticut state legislators came close to adopting a bill that would have cut the state’s 20-percent RPS down to 11.5 percent. Other states reportedly are considering adding safety-valve provisions to RPS mandates that don’t already have them, with language protecting consumers from costs that exceed a defined figure.</p>
<p>At the same time, however, the U.S. Congress is once again contemplating a national RES, which could remove some of the perennial uncertainty and patchwork policies that have stunted the growth of renewables. But even if such legislation can make it to the finish line during the coming lame-duck session, renewable energy developers still face the near-term challenge of competing in a market seemingly flooded with cheap gas.</p>
<p>“Prices for renewable energy are going down, especially for solar PV. But still, natural gas is a big hurdle to overcome,” Cohen says. “Without a big stimulus it will be a struggle for a lot of renewable energy deals, especially smaller projects.” The same can be said for the developers in the market; the coming down cycle could consolidate the business, with better capitalized players acquiring those that can’t find financing to continue development.</p>
<p>On the other hand, low gas prices—along with declining coal-fired capacity and continued transmission constraints—are setting the stage for a boom in construction of combined-cycle gas turbine (CCGT) power plants, particularly given the long lead time for other base-load construction options, such as nuclear and coal gasification.</p>
<p>“When the economy rebounds, electricity demand likely will be right back where it was before the recession,” Napolitano says. “Many coal plants have fallen out of the queue, and something needs to fill the gap. At today’s prices, that something is CCGT.”</p>
<p>The most recent <i>EIA Annual Energy Outlook</i> anticipates more than 20 GW will be built through 2020, and by some estimates more than half that amount already has begun development. Because they’re so competitive in an environmentally constrained power market, gas-fired projects are well positioned to obtain financing, whether they’re built within the utility rate base or an unregulated portfolio.</p>
<p>“The project financing market has re-opened,” Nastro says. “Liquidity has improved substantially in the capital markets, as project investors seek new and diversified asset classes. And as a result, clean energy is dominating the project debt pipeline.”</p>
<h4>M&amp;A Synergy</h4>
<p>The same market trends that favor construction of new CCGT plants also make existing gas-fired capacity more attractive; the previous glut of gas-fired power seems likely to disappear in many regions as more coal plants retire and as electricity consumption rises. And indeed, many recent M&amp;A transactions have revolved around existing gas-turbine capacity—including individual plants and also entire portfolios. Examples include Constellation’s offer to acquire the bankrupt Boston Generating; Blackstone’s planned acquisition of Dynegy and subsequent sale of several gas-fired plants to NRG; and Calpine’s $1.65 billion buyout of the former Conectiv generating assets owned by PEPCO.</p>
<p>“We’re seeing acquisitions happen where it’s cheaper to buy than build,” says John McConomy, a lead partner at Pricewaterhouse Coopers LLP. “We’ll see a significant number of merchant plant sales in the next 15 months or so. This is driven by timing. When the economy went bad, commodity prices and industrial demand went down, and the owners of plants that were only five or six years old didn’t have what they needed to finance their debt.”</p>
<p>Now, strategic buyers and some private equity and institutional investors are buying generating assets while they’re still relatively cheap—especially, but not only, gas-fired plants. “Across the generation sector, valuations have been down in large part because of the cost of gas,” says Bill Lamb, a partner at Dewey &amp; LeBoeuf.</p>
<p>In recently announced transactions, for example, CCGT plants have been valued between $300 and $500 a kilowatt—a huge bargain considering new capacity can cost $1,200 or more to build.</p>
<p>“Companies are buying merchant plants at half cost today, and getting ahead of the demand curve,” Napolitano says. “They’re making a bet that capacity tightness will drive power prices up, and they’ll see a fair return for their investment.”</p>
<p>The value of generating assets also has factored into strategic deals involving companies such as Sempra Energy, which in late September announced a deal to sell its RBS-Sempra Commodities joint venture to Singaporean commodities trading company Noble Group Ltd. At press time, Sempra was negotiating to sell its Connecticut-based wholesale power and gas business. The sales are part of Sempra’s strategy to exit the commodities business.</p>
<p>“Companies are unlocking value by reducing their overall risk profile, with an emphasis on business model clarity,” Nastro says. “Hybrid companies continue to review their business mix, with a focus on non-core assets, in order to make sure they’re fairly valued in the equity market.”</p>
<p>Additionally, many recent M&amp;A deals seem aimed at reducing risks through market diversification, and capturing scale economy and cost synergy. Examples include the mergers of integrated utilities FirstEnergy and Allegheny, as well as merchant generators Mirant and RRI; United Illuminating’s planned acquisition of three gas utilities from Iberdrola; Chesapeake Utilities’ acquisition of Florida Public Utilities; and PPL’s bid to acquire E.On U.S.</p>
<p>“Resource uncertainties play a significant role in most transactions,” McConomy says. “But the underlying theme is that if you’re going to grow your company and increase shareholder returns, you have to find a way to generate more bottom-line income. One way to do that is by becoming a bigger company that can deliver synergies, and that theoretically has better access to the capital needed to build assets.”</p>
<p>Whether the recent series of M&amp;A announcements portends a coming wave of transactions, however, depends in part on the fate of the current deals—particularly those involving regulated utility assets. Ironically, the shaky economy might actually help some companies make their case to regulators. Where state PUCs previously killed some deals by demanding large ratepayer concessions, regulators today might be more receptive to mergers that simply reduce or delay the need for future rate hikes. PPL, for example, has overcome some objections to the E.On U.S. acquisition by pledging to hold rates steady until at least 2013.</p>
<p>“To the extent two companies can merge together and have rates increase less than they would if the companies continued on a stand-alone basis, regulators should view that as favorable,” Hempstead says.</p>
<p>Further, if some of the current deals make it all the way to the finish line, they might provide a roadmap for others to follow. For instance, merging companies might find greater success by being more conservative and less specific about the dollar value of synergies they expect transactions to deliver. “The environment for consolidation is better now than it’s been for a few years,” McConomy says. “Companies are looking at who to team up with, and how to bring the best value to shareholders. But regulated utilities have to be careful to understand the mindset of PUCs.”</p>
<p>Thus as a general matter, corporate-level M&amp;A seems unlikely to accelerate very dramatically in the United States, mostly because deals remain complex and difficult to sell to state regulators.</p>
<p>“There are so many different pieces that must line up to make deals worthwhile, I don’t see the floodgates opening,” Lamb says. “I wouldn’t expect to see more than a few deals in the $2 billion-plus range in the next 12 months.”</p>
<h4>Building the Buzz</h4>
<p>Even if M&amp;A announcements aren’t coming fast and furious, the increased pace of deals this year compared to the previous two years signals a decidedly improving outlook for the U.S. power and gas industry. Companies have gained enough confidence about the future that they’re considering strategic moves—mostly aimed at strengthening core businesses and achieving greater scale and market diversity. These are all good things, and Wall Street seems ready to reward companies for making such moves.</p>
<p>Accordingly, companies that are planning to increase their capital spending programs can expect a warm reception—at least on Wall Street. Whether regulators and customers embrace the higher prices that result from higher cap-ex likely will depend on how effectively utilities make the case for such investments—and how they fit into the evolving regulatory and economic picture. In the meantime, power and gas companies are dealing with uncertainties in the market by raising capital and making strategic moves that seem rational in the context of today’s changing outlook. Infrastructure investments likely will grow apace as that outlook solidifies.</p>
<p>“The longer the industry faces uncertainties, the harder it will be to plan for the future,” says Mike Haggerty, a senior credit officer with Moody’s. “Companies can plan strategically for six months or a year, but planning beyond that will depend on the answers to long-run questions.”</p>
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<a href="/tags/american-recovery-and-reinvestment-act">American Recovery and Reinvestment Act</a><span class="pur_comma">, </span><a href="/tags/andy-redinger">Andy Redinger</a><span class="pur_comma">, </span><a href="/tags/annual-energy-outlook">Annual Energy Outlook</a><span class="pur_comma">, </span><a href="/tags/arra">ARRA</a><span class="pur_comma">, </span><a href="/tags/barclays">Barclays</a><span class="pur_comma">, </span><a href="/tags/barclays-capital">Barclays Capital</a><span class="pur_comma">, </span><a href="/tags/bc">BC</a><span class="pur_comma">, </span><a href="/tags/calpine">Calpine</a><span class="pur_comma">, </span><a href="/tags/cash-flow">cash flow</a><span class="pur_comma">, </span><a href="/tags/ccgt">CCGT</a><span class="pur_comma">, </span><a href="/tags/chesapeake-utilities">Chesapeake Utilities</a><span class="pur_comma">, </span><a href="/tags/clean-air-act">Clean Air Act</a><span class="pur_comma">, </span><a href="/tags/congress">Congress</a><span class="pur_comma">, </span><a href="/tags/constellat">Constellat</a><span class="pur_comma">, </span><a href="/tags/constellation">Constellation</a><span class="pur_comma">, </span><a href="/tags/david-nastro">David Nastro</a><span class="pur_comma">, </span><a href="/tags/dynegy">Dynegy</a><span class="pur_comma">, </span><a href="/tags/eon">E.On</a><span class="pur_comma">, </span><a href="/tags/eia-0">EIA</a><span class="pur_comma">, </span><a href="/tags/energy-information-administration-0">Energy Information Administration</a><span class="pur_comma">, </span><a href="/tags/epa">EPA</a><span class="pur_comma">, </span><a href="/tags/epa-rules">EPA rules</a><span class="pur_comma">, </span><a href="/tags/epc">EPC</a><span class="pur_comma">, </span><a href="/tags/firstenergy">FirstEnergy</a><span class="pur_comma">, </span><a href="/tags/frank-napolitano">Frank Napolitano</a><span class="pur_comma">, </span><a href="/tags/ghg">GHG</a><span class="pur_comma">, </span><a href="/tags/goldman-sachs">Goldman Sachs</a><span class="pur_comma">, </span><a href="/tags/infrastructure">Infrastructure</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/itc">ITC</a><span class="pur_comma">, </span><a href="/tags/james-hempstead">James Hempstead</a><span class="pur_comma">, </span><a href="/tags/keybanc">KeyBanc</a><span class="pur_comma">, </span><a href="/tags/keybanc-capital-markets">KeyBanc Capital Markets</a><span class="pur_comma">, </span><a href="/tags/mike-haggerty">Mike Haggerty</a><span class="pur_comma">, </span><a href="/tags/morgan-stanley">Morgan Stanley</a><span class="pur_comma">, </span><a href="/tags/natural-gas">Natural gas</a><span class="pur_comma">, </span><a href="/tags/nrg">NRG</a><span class="pur_comma">, </span><a href="/tags/pepco">PEPCO</a><span class="pur_comma">, </span><a href="/tags/ppl">PPL</a><span class="pur_comma">, </span><a href="/tags/pv">PV</a><span class="pur_comma">, </span><a href="/tags/rbc">RBC</a><span class="pur_comma">, </span><a href="/tags/rbc-capital-markets">RBC Capital Markets</a><span class="pur_comma">, </span><a href="/tags/rbs">RBS</a><span class="pur_comma">, </span><a href="/tags/recovery">Recovery</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/renewable-power">Renewable power</a><span class="pur_comma">, </span><a href="/tags/res">RES</a><span class="pur_comma">, </span><a href="/tags/rps">RPS</a><span class="pur_comma">, </span><a href="/tags/sempra">Sempra</a><span class="pur_comma">, </span><a href="/tags/sempra-energy">Sempra Energy</a><span class="pur_comma">, </span><a href="/tags/tim-kingston">Tim Kingston</a><span class="pur_comma">, </span><a href="/tags/us-energy-information-administration">U.S. Energy Information Administration</a><span class="pur_comma">, </span><a href="/tags/wind">Wind</a> </div>
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Fri, 01 Oct 2010 04:00:00 +0000puradmin13588 at http://www.fortnightly.comMiddle Mile Moxiehttp://www.fortnightly.com/fortnightly/2010/01/middle-mile-moxie
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Michael T. Burr</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">People in Power</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Michael T. Burr</b> is <em>Fortnightly’s</em> editor-in-chief. Email him at <a href="mailto:burr@pur.com">burr@pur.com</a>.<b> </b></p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - January 2010</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>As chief architect of Xcel Energy’s Smart Grid City project in Boulder, Colo., Ray Gogel served on the front lines in the industry’s technology revolution.</p>
<p>With the Smart Grid City project, Xcel proposes to create America’s first fully functional intelligent grid, with communications and automation systems linking the network from end to end, power plants to meters. Although Xcel still is deploying the system, Gogel says the project already has yielded some important results. Most notably, it’s shown that the early payoff from smart-grid investments won’t necessarily come from automated metering, but from automation in the distribution network—the “middle mile.”</p>
<p>Moreover, he says, these investments are driving the industry toward a new world of risks and opportunities for utilities.</p>
<p><i>Fortnightly </i>spoke with Gogel in late 2009, after he left Xcel to take the helm at Current Group—one of the companies that’s providing distribution automation technology for Xcel’s Smart Grid City.</p>
<p> </p>
<p><b>Fortnightly: What do you mean by the “middle mile,” and why is it important? </b></p>
<p><b>Gogel</b><b>: </b>The smart grid started when people realized we should re-engineer the existing grid, because its design principles were fundamentally flawed. The distribution system was designed to run to failure. When it failed, customers would complain, and that was the intelligence in the value chain. That’s not a business model that most industries can survive with, but we’ve done it for decades.</p>
<p>What I see now is a deepening of thought. First people began asking how we’ll leverage technology in the last mile to bring customers into the system. The middle mile is the next step in the grid’s evolution.</p>
<p>Traditionally, we’ve had very little visibility beyond the transformer. Xcel Energy’s Boulder pilot showed that if you can light up every transformer and see the voltage that’s there, you can use software to analyze quickly what’s taking place, and you can use the same software to control network elements, like load tap changers and capacitor banks. If you can start manipulating a complex grid on the fly, you can deal with VARs automatically. You can improve power factors and reduce losses.</p>
<p>First, you make the grid transparent, then you put in automated controls, and then the middle mile becomes an optimization play. For example, it becomes the condition of possibility for energy to flow in both directions. If you can anticipate bilateral flows and consider multiple inputs on a feeder-by-feeder basis, then you can manage distributed generation and plug-in hybrid electric vehicles (PHEV) that will be coming onto the grid.</p>
<p>This leads to some interesting possibilities. In the new world, companies will aggregate distributed generators on peoples’ houses, similar to the way EnerNOC or Comverge aggregate demand response, and they’ll make automation investments in the middle mile that will allow them to create and sell virtual power. They’ll back it up with traditional offerings, but their role fundamentally revolutionizes and accelerates the evolution of the smart grid.</p>
<p> </p>
<p><b>Fortnightly</b><b>: How might these changes affect the evolution of electricity markets? </b></p>
<p><b>Gogel</b><b>: </b>The market will have to change, because we’ll be looking at smaller pieces of the puzzle to dispatch. Can you imagine a day when we’re aggregating distributed resources as a first call for energy into a feeder, instead of just calling on bigger bulk-power plays? The future won’t be about just [base-load plant] retrofits and building peaking plants. And the nature of the peaking plant is fundamentally changing, because the more volatility you put on the grid, the more backup you need. Peakers will be running more than they were before.</p>
<p>As for retail markets, I’m not yet a believer that retail markets fundamentally will shift, and I believe utilities are a very efficient way to make capital investments. But we have to change the model so utilities aren’t making their money on iron in the ground and sales volume. The revenue model has to change so utilities make their money on innovation and cleverness. But that also means we have to get away from this Monday-morning quarterback practice where the regulators say an investment wasn’t prudent because it was imperfect. That doesn’t encourage innovation. Instead it maintains the <i>status quo</i>. The market should reward innovation and new entrants into the industry, and we should change any framework that doesn’t reward that.</p>
<p> </p>
<p><b>Fortnightly</b><b>: That would require some fundamental changes in the business model. Isn’t that asking a lot of the industry? </b></p>
<p><b>Gogel</b><b>: </b>Well, we are asking a lot already. We’re asking utilities to change the tires while they’re driving the car. Going from a product mentality to a service mentality requires re-engineering our whole delivery model. Contacts with shareholders, employees and consumers are fundamentally shifting.</p>
<p> </p>
<p><b>Fortnightly</b><b>: What lessons have been learned so far from Xcel’s Smart Grid City project? </b></p>
<p><b>Gogel</b><b>: </b>Obviously there’s much more yet to be seen, but the initial results are coming from the middle mile, the distribution grid. They’re around things that don’t sound as sexy as PHEVs, but are really important to the charter of the utility. We know, for instance, that service investigations resulting from voltage fluctuations at the customer premise went from 50 in 2007, before the smart build out, to zero thus far in 2009. Admittedly that’s not a huge universe, but it shows the benefits of making the grid proactive, where you can see every transformer and use software to analyze the data and make recommendations. There hasn’t been a transformer event that the software hasn’t predicted. It’s going from a reactive world, where you run to fail, to a world where you can dispatch resources to avoid outages. I hope soon we’ll see how dynamic voltage optimization is implemented and what consequences that has for the grid in general.</p>
<p>Also we’re still awaiting results around customer buy-in, the use of smart meters, changing lifestyles, all those things. It’s too early to judge, and you have to be realistic when you talk about disruptive technologies changing people’s behavior. Until the technology is smooth and sophisticated—which isn’t the definition of disruptive technology—people’s lifestyles won’t change. It will take a generation for it to happen.</p>
<p>But Boulder is proving that utilities are willing to rethink their traditional business models. They’re willing and able to take risks and be innovative.</p>
<p>And it’s showed how vendors and utility departments can come together and drive innovation. By focusing on their customers, utilities can start tying together different silos. They can work together and create something new. In fact, if people go naively into the smart grid and don’t think about how they will manage across silos, they’ll inevitably fail.</p>
<p> </p>
<p><b>Fortnightly</b><b>: Xcel is known for managing successful collaborations, with things like its Utility Innovations initiative and now the Boulder project. How is that accomplished? </b></p>
<p><b>Gogel: </b>You create strategic advisory boards, with not only technical people but also CEOs of different companies. That’s what we did at Boulder, going back to 2002. The selection process focused on functionality, and also on each entity’s ability to partner with other players.</p>
<p>The tricky part is handling the creation of new intellectual property. It requires discipline on everybody’s part.</p>
<p> </p>
<p><b>Fortnightly</b><b>: What do you see as the biggest questions now as the smart grid emerges in the context of changing energy policies? </b></p>
<p><b>Gogel</b><b>: </b>We’re at the beginning of a journey, and so far it’s been successful in that a dialogue is taking place among stakeholders. However, by injecting real innovation into the space, you’re going to change the paradigms. We’ve got to find ways to keep utilities whole in that process.</p>
<p>Sometimes in policy debates we forget the fact that in this industry people go out and climb poles in the middle of ice storms and hurricanes, to keep consistently delivering power to customers. This is a job of a higher order. Utilities are maintaining their franchises and their charters, and we’re making their lives significantly more complicated. We’re tapping into the fifth fuel. Renewable power producers are entering the market, and there’s a movement toward cap-and-trade, with a lot of unanswered questions.</p>
<p>A key question is how we drive this concept of virtual power, of conjoining supply and demand and managing them at the distribution level. How do you make virtual power a reality, not just to serve the 40 to 80 hours of critical peak each year, but for the other 8,700 hours as well? It’s in the consumer’s interest, but how are regulators going to treat the hard work and innovation utilities are doing? Utilities should be compensated for doing that work and managing those risks—with multiples—but charters have to be reinvented one step at a time.</p>
<p>There’s a lot of hard work to be done, and there’s a lot of opportunity. I’m looking forward to the best and brightest companies showing what the grid can be.</p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/smart-grid">Smart Grid</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/people-power">People In Power</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1001/images/1001-PIP.jpg" width="817" height="772" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/comverge">Comverge</a><span class="pur_comma">, </span><a href="/tags/enernoc">EnerNOC</a><span class="pur_comma">, </span><a href="/tags/ev">EV</a><span class="pur_comma">, </span><a href="/tags/evs">EVs</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/innovation">Innovation</a><span class="pur_comma">, </span><a href="/tags/phev">PHEV</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/renewable-power">Renewable power</a><span class="pur_comma">, </span><a href="/tags/smart-grid-city">Smart Grid City</a><span class="pur_comma">, </span><a href="/tags/xcel-energy">Xcel Energy</a> </div>
</div>
Fri, 01 Jan 2010 05:00:00 +0000puradmin14251 at http://www.fortnightly.com